Canadian Natural Resources Limited Announces 2024 First Quarter Results

Canadian Natural's (TSX: CNQ) (NYSE: CNQ) President, Scott Stauth, commented on the Company's first quarter results, "Canadian Natural is a world class company and during our 35 years of operations, we've delivered significant value, including recently reaching a position where, commencing in 2024, we are returning 100% of our free cash flow to our shareholders. Crude oil price forecasts have strengthened for the remainder of 2024, including improvements in West Texas Intermediate ("WTI"), Western Canadian Select ("WCS") and Synthetic Crude Oil ("SCO") pricing over those prices experienced in the first quarter of 2024, driving significant targeted free cash flow generation going forward.

Canadian Natural's large, unique and diversified asset base provides a key competitive advantage enabling us to effectively allocate capital across our asset base and manage the pace and timing of development activities, maximizing value for our shareholders. We are executing on our 2024 plan which is strategically weighted to longer cycle thermal development projects in the first half of the year and shorter cycle growth projects in the second half of the year, which aligns with increased market egress and improved forward strip crude oil pricing. As a result, we target to finish the year with strong exit rates as conventional activity ramps up in the second half of the year.

In Oil Sands Mining and Upgrading, at the Horizon site, we are well prepared for 2024 turnaround activity and final tie ins of the reliability enhancement project in the second quarter of the year which will be followed by targeted strong production in the second half of the year with high upgrader utilization. Through optimization efforts and early turnaround work done in early 2024, we have reduced the Horizon turnaround to 28 days from 30 days and improved the commissioning schedule for the reliability enhancement project. These optimizations will advance and shorten commissioning timing after the turnaround to support high targeted utilization and production rates in the second half of the year.

We have a defined path to reduce our environmental footprint and continue delivering sustainable, responsibly produced energy that the world needs. We are committed to supporting Canada's and Alberta's climate goals and have robust environmental targets, including net zero greenhouse gas ("GHG") emissions for the oil sands by 2050. We are uniquely positioned with diverse, long life low decline assets, which are ideal for applying GHG reduction technologies and providing industry leading environmental performance. It is important to continue working together with the Canadian and Alberta governments to make the Pathways Alliance a transformative industry collaboration and achieve meaningful GHG reductions in Canada. We believe Canadian energy is one of the most responsibly produced sources of energy in the world and should be the preferred energy choice."

Canadian Natural's Chief Financial Officer, Mark Stainthorpe, also added, "In Q1/24, we delivered strong financial results, including adjusted net earnings of approximately $1.5 billion and adjusted funds flow of $3.1 billion, which drove significant returns to shareholders totaling $1.7 billion in the quarter. Commencing in 2024, we are returning 100% of free cash flow to shareholders, as per our free cash flow allocation policy, and continue to manage the allocation on a forward looking annual basis.

At Canadian Natural, our culture of continuous improvement and employee ownership alignment with shareholders drives our teams to create significant value across all areas of the Company. Our effective and efficient operations combined with our flexible capital allocation maximizes value for our shareholders."

HIGHLIGHTS

			Three Months Ended
($ millions, except per common share amounts)			Mar 31 2024		Dec 31 2023		Mar 31 2023
Net earnings		$	987	$	2,627	$	1,799
Per common share	- basic	$	0.92	$	2.43	$	1.63
	- diluted	$	0.91	$	2.41	$	1.62
Adjusted net earnings from operations⁽¹⁾		$	1,474	$	2,546	$	1,881
Per common share	- basic⁽²⁾	$	1.38	$	2.36	$	1.71
	- diluted⁽²⁾	$	1.37	$	2.34	$	1.69
Cash flows from operating activities		$	2,868	$	4,815	$	1,295
Adjusted funds flow⁽¹⁾		$	3,138	$	4,419	$	3,429
Per common share	- basic⁽²⁾	$	2.93	$	4.09	$	3.12
	- diluted⁽²⁾	$	2.91	$	4.05	$	3.08
Cash flows used in investing activities		$	1,392	$	946	$	1,153
Net capital expenditures⁽³⁾		$	1,113	$	975	$	1,257
Abandonment expenditures		$	162	$	149	$	137
Daily production, before royalties
Natural gas (MMcf/d)			2,147		2,231		2,139
Crude oil and NGLs (bbl/d)			975,668		1,047,541		962,908
Equivalent production (BOE/d)⁽⁴⁾			1,333,502		1,419,313		1,319,391
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024. (2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024. (3)Non-GAAP Financial Measure. The composition of this measure was updated in the fourth quarter of 2023 and has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024. (4)A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The strength of Canadian Natural's long life low decline asset base, supported by safe, effective and efficient operations, makes our business unique, robust and sustainable. In Q1/24, the Company generated strong financial results, including:
- Net earnings of approximately $1.0 billion and adjusted net earnings from operations of approximately $1.5 billion.
- Cash flows from operating activities of approximately $2.9 billion.
- Adjusted funds flow of approximately $3.1 billion.
Canadian Natural continues to maintain a strong balance sheet and financial flexibility, with approximately $6.8 billion in liquidity⁽¹⁾ as at March 31, 2024.
- Subsequent to quarter end, the Company repaid US$0.5 billion of 3.8% debt securities due April 15, 2024.
Canadian Natural achieved its $10 billion net debt level at year end 2023 and is returning 100% of free cash flow⁽¹⁾ in 2024 to shareholders, per the Company's free cash flow allocation policy. The Company will manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.

(1) Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of this press release and the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.

Canadian Natural continues to focus on safe, effective and efficient operations, and delivered quarterly average production in Q1/24 of 1,333,502 BOE/d, consisting of total liquids production of 975,668 bbl/d and natural gas production of 2,147 MMcf/d.
The Company is targeting strong production from its Oil Sands Mining and Upgrading assets in the second half of the year, as we optimize turnaround activity, complete final tie ins and advance commissioning of the reliability enhancement project in Q2/24.
Canadian Natural has significant growth opportunities across its asset base, including sustainable production enhancements at its Oil Sands Mining and Upgrading operations.
- Near-term projects include the reliability enhancement project at Horizon, which targets to increase the two-year average SCO capacity by approximately 14,000 bbl/d by extending the turnaround schedule to once every two years. Additionally, the debottlenecking project at the Scotford Upgrader targets to add incremental capacity at the Athabasca Oil Sands Project ("AOSP") of approximately 5,600 bbl/‌d net to Canadian Natural.
- Medium-term projects include the Naphtha Recovery Unit Tailings Treatment ("NRUTT") project at Horizon, which targets to add incremental production of approximately 6,300 bbl/d of SCO, reduce GHG emissions and lower reclamation costs.
- Long-term projects at our Oil Sands operations include combining In-Pit Extraction Process ("IPEP") and Paraffinic Froth Treatment ("PFT") that have the potential to add approximately 195,000 bbl/d of additional annual bitumen production, reduce GHG emissions and lower reclamation costs.
The Company's 2024 development plan has conventional activity strategically weighted to the second half of 2024 to better align with increased market egress and improved crude oil pricing, maximizing value for our shareholders. Following completion of the Trans Mountain Expansion ("TMX") pipeline, there will be ample egress and optionality for our crude oil products.
- Strong free cash flow generation is targeted in the last nine months of the 2024, given improved crude oil forward strip pricing as of April 30, 2024:
  - WTI of US$79.95/bbl, an improvement of approximately US$3/bbl from US$76.97/‌bbl experienced in Q1/24.
  - SCO at a US$2.47/bbl price premium to WTI, an improvement of approximately US$10/‌bbl from a US$7.54/‌bbl discount experienced in Q1/24.
  - WCS differential strengthening to a discount to WTI of US$13.17/‌bbl, an improvement of approximately US$6‌/‌bbl from the US$19.34/‌bbl discount experienced in Q1/24.
The Company continues to evaluate and implement opportunities to maximize netbacks through the diversification of sales and optimized blending and transportation options through diverse market access. Canadian Natural has optionality for crude oil exports, including the following pipeline commitments:
- In Q1/24, the Company increased its commitment on Flanagan South by 55,000 bbl/d to 77,500 bbl/d, further expanding the Company's heavy oil diversification and market access to the United States Gulf Coast ("USGC").
- 94,000 bbl/d on Trans Mountain Expansion ("TMX") pipeline that creates additional crude oil market diversification opportunities on the west coast, both by land and by water.
- 10,000 bbl/d on the Base Keystone Pipeline, with direct access to the USGC.

RETURNS TO SHAREHOLDERS

Canadian Natural has a strong history of growing its sustainable dividend for 24 consecutive years and commencing in 2024, we are now returning 100% of free cash flow to shareholders.
- Returns to shareholders in Q1/24 were strong, totaling approximately $1.7 billion, comprised of $1.1 billion of dividends and $0.6 billion through the repurchase and cancellation of approximately 6.7 million common shares at a weighted average price of $90.78 per share.
- Year to date in 2024, up to and including May 1, 2024, the Company has returned a total of approximately $3.1 billion directly to shareholders through $2.2 billion in dividends and $0.9 billion through the repurchase and cancellation of approximately 9.6 million common shares.
- Subsequent to quarter end, the Company declared a quarterly cash dividend on its common shares of $1.05 (one dollar and five cents) per common share on a pre-stock split basis or $0.525 (fifty-two and one half cents) per common share after the two for one share split of the common shares, subject to shareholder approval at the Company's Annual and Special Meeting of Shareholders on May 2, 2024. The quarterly dividend will be payable on July 5, 2024 to shareholders of record at the close of business on June 17, 2024.
  - As previously announced on February 29, 2024, the Board of Directors increased the quarterly dividend by 5% to $1.05 per common share. This demonstrates the confidence that the Board of Directors has in the sustainability of our business model, our strong balance sheet and the strength of our diverse, long life low decline reserves and asset base. The Company's leading track record of dividend increases continues, with 2024 being the 24^th consecutive year of dividend increases with a compound annual growth rate ("CAGR") of 21% over that time.
On February 28, 2024, Canadian Natural's Board of Directors approved a resolution to subdivide the Company's common shares on a two for one basis, subject to shareholder approval at the Company's Annual and Special Meeting of Shareholders on May 2, 2024. The Company will also be required to obtain all regulatory approvals, including TSX approval.

OPERATIONS REVIEW AND CAPITAL ALLOCATION

Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the UK section of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light crude oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil) and SCO (herein collectively referred to as "crude oil") and natural gas and NGLs. This balance provides optionality for capital investments, maximizing value for the Company's shareholders.

Underpinning this asset base is the Company's long life low decline production, representing approximately 79% of total budgeted liquids production in 2024, the majority of which is zero decline high value SCO production from the Company's world class Oil Sands Mining and Upgrading assets. The remaining balance of the Company's long life low decline production comes from its top tier thermal in situ oil sands operations and Pelican Lake heavy crude oil assets. The combination of these long life low decline assets, low reserves replacement costs, and effective and efficient operations results in substantial and sustainable adjusted funds flow throughout the commodity price cycle.

In addition, Canadian Natural maintains a substantial inventory of low capital exposure projects within the Company's conventional asset base. These projects can be executed quickly and, in the right economic conditions, provide excellent returns and maximize value for our shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable drilling programs that can be optimized over time. Additionally, Canadian Natural maximizes long-term value by maintaining high ownership and operatorship of its assets and has an extensive infrastructure network, allowing the Company to control the nature, timing and extent of development. Low capital exposure projects can be stopped or started relatively quickly depending upon success, market conditions or corporate needs.

Canadian Natural's balanced portfolio, built with both long life low decline assets and low capital exposure assets, enables effective capital allocation, production growth and value creation.

Drilling Activity	Three Months Ended
	Mar 31, 2024		Mar 31, 2023
(number of wells)	Gross	Net	Gross	Net
Crude oil⁽¹⁾	62	61	88	83
Natural gas	23	16	26	21
Dry	-	-	2	2
Subtotal	85	77	116	106
Stratigraphic test / service wells	452	386	455	394
Total	537	463	571	500
Success rate (excluding stratigraphic test / service wells)		100%		98 %
(1)Includes bitumen wells.

Canadian Natural drilled a total of 77 net crude oil and natural gas producer wells in Q1/24 compared to 106 net wells in Q1/23, a decrease of 29 net wells over this time period. This decrease in drilling activity reflects the Company's strategic decision to focus on longer cycle development opportunities in the first half of 2024 and shorter cycle development opportunities in the second half of 2024, as previously outlined in the Company's 2024 budget press release.

North America Exploration and Production

Crude oil and NGLs - excluding Thermal In Situ Oil Sands
	Three Months Ended
	Mar 31 2024	Dec 31 2023	Mar 31 2023
Crude oil and NGLs production (bbl/d)	237,481	243,157	234,465
Net wells targeting crude oil	38	42	60
Net successful wells drilled	38	42	58
Success rate	100%	100 %	97 %

North America E&P liquids production, excluding thermal in situ, averaged 237,481 bbl/d in Q1/24, comparable to Q1/23 levels. As previously outlined in the 2024 budget, the Company has strategically allocated capital for its conventional assets to the latter part of 2024 to better align with incremental market egress, driving strong targeted 2024 exit rates.
- Primary heavy crude oil production averaged 78,431 bbl/d in Q1/24, comparable to Q1/23 levels, reflecting strong results from the Company's multilateral wells in the Mannville and Clearwater fairways which offset natural field declines.
  - The Company is targeting to drill 148 net multilateral wells in 2024, 12 more than budgeted, as we are shifting certain dry natural gas activity to these higher returning multilateral heavy oil wells. The majority of this activity is strategically planned for the second half of 2024.
  - Operating costs⁽¹⁾ in the Company's primary heavy crude oil operations averaged $19.16/bbl (US$14.21/‍bbl) in Q1/24, a decrease of 11% from Q1/23 levels, primarily reflecting lower energy costs.
- Pelican Lake production averaged 45,145 bbl/d in Q1/24, a decrease of 6% from Q1/23 levels, reflecting low natural field declines from this long life low decline asset.
  - Operating costs at Pelican Lake averaged $9.75/bbl (US$7.23/bbl) in Q1/24, comparable to Q1/23 levels.
- North America light crude oil and NGLs production averaged 113,905 bbl/d in Q1/24, an increase of 5% from Q1/23 production which was impacted by a third party pipeline outage. Production in Q1/24 reflects strong drilling results from the Company's liquids-rich Montney and Deep Basin assets partially offset by natural field declines.
  - Operating costs in the Company's North America light crude oil and NGLs operations averaged $15.25/‍bbl (US$11.31/bbl) in Q1/24, a decrease of 18% from Q1/23 levels, reflecting increased production and lower energy costs.

North America Natural Gas
	Three Months Ended
	Mar 31 2024	Dec 31 2023	Mar 31 2023
Natural gas production (MMcf/d)	2,135	2,218	2,127
Net wells targeting natural gas	16	9	21
Net successful wells drilled	16	9	21
Success rate	100%	100 %	100 %

Canadian Natural's North America natural gas production averaged 2,135 MMcf/d in Q1/24, comparable to Q1/23 production which was impacted by a third party pipeline outage. Production in Q1/24 reflects strong results from the Company's capital efficient drill to fill development plan, offset by natural field declines.
- North America natural gas operating costs averaged $1.27/Mcf in Q1/24, a decrease of 11% from Q1/23 levels, primarily reflecting lower energy costs.

(1) Calculated as production expense divided by respective sales volumes. Natural gas and NGLs production volumes approximate sales volumes.

Thermal In Situ Oil Sands
	Three Months Ended
	Mar 31 2024	Dec 31 2023	Mar 31 2023
Bitumen production (bbl/d)	268,155	278,422	242,884
Net wells targeting bitumen	23	-	25
Net successful wells drilled	23	-	25
Success rate	100%	- %	100 %

Thermal in situ long life low decline production averaged 268,155 bbl/d in Q1/24, an increase of 10% from Q1/23 levels, driven by strong execution on Cyclic Steam Stimulation ("CSS") and Steam Assisted Gravity Drainage ("SAGD") pad developments in 2023.
- Thermal in situ operating costs averaged $14.05/bbl (US$10.42/bbl) in Q1/24, a decrease of 12% from Q1/23 levels, primarily reflecting higher production volumes and lower energy costs.
The Company successfully completed the planned turnaround at Jackfish ahead of schedule in April 2024, and has an upcoming turnaround at Kirby North in May 2024. As a result of completing the turnaround at Jackfish ahead of schedule, the total impact to Q2/24 average production is now targeted to be approximately 15,300 bbl/d, an improvement from the previous target of 17,100 bbl/d.
Canadian Natural has decades of strong capital efficient growth opportunities on its long life low decline thermal in situ assets. As outlined in our 2024 budget, we continue to develop these assets in a disciplined manner to deliver safe and reliable thermal in situ production with the following opportunities:
- At Primrose, the Company is currently drilling two CSS pads which are targeted to come on production in Q2/25. At Wolf Lake, the Company recently drilled one SAGD pad which is targeted to come on production in Q1/25.
- At Jackfish, the first of two SAGD pads that were drilled in 2023 has ramped up to its targeted full production capacity in April 2024, ahead of budget. The second pad is targeted to ramp up to its full production capacity in Q4/24, supporting continued high utilization rates at the Jackfish facilities. Additionally, the Company is targeting to drill one SAGD pad at Jackfish in the second half of 2024, with production from this pad targeted to come on in Q3/25.
Canadian Natural has been piloting solvent enhanced oil recovery technology on certain thermal in situ assets with an objective to increase bitumen production while reducing the Steam to Oil Ratio ("SOR") and GHG intensities by 40% to 50% and optimizing solvent recovery. This technology has the potential for application throughout the Company's extensive thermal in situ asset base.
- At Kirby North, the commercial scale solvent SAGD pad development is approximately 90% complete and the Company is targeting to begin solvent injection in July 2024.
- At Primrose, the Company is continuing to use its solvent enhanced oil recovery pilot in the steam flood area to optimize solvent efficiency and to further evaluate the commercial development opportunity.

North America Oil Sands Mining and Upgrading

	Three Months Ended
	Mar 31 2024	Dec 31 2023	Mar 31 2023
Synthetic crude oil production (bbl/d) ⁽¹⁾⁽²⁾	445,209	500,133	458,228
(1)SCO production before royalties and excludes production volumes consumed internally as diesel. (2)Consists of heavy and light synthetic crude oil products.

Canadian Natural remains focused on safe, reliable, effective and efficient operations of its world class Oil Sands Mining and Upgrading assets. In Q1/24, the Company delivered average production of 445,209 bbl/d of high value SCO, a decrease of 3% from Q1/23 levels. Production in Q1/24 reflected planned and unplanned maintenance activities, including the advancement of the Scotford Upgrader planned turnaround to March 2024 from April 2024. These activities in Q1/24 reduced Oil Sands Mining and Upgrading production by approximately 45,000 bbl/d of SCO from what would have been achieved otherwise. Through the actions discussed below and other optimization efforts, the Company is targeting to recover these daily production volumes in the last three quarters of 2024.
- Oil Sands Mining and Upgrading operating costs are top tier, averaging $24.85/bbl (US$18.43/bbl) in Q1/24, comparable to Q1/23 levels.
Canadian Natural has the following upcoming turnarounds, including schedule optimizations, planned at our Oil Sands Mining and Upgrading operations:
- At Horizon, a planned turnaround is targeted to begin on May 15, 2024. Through continuous improvement, optimization efforts and early turnaround work done in Q1/24 during unplanned maintenance activities, the Company has reduced the targeted duration of the turnaround to 28 days from 30 days.
  - Additionally, following the turnaround, the Company is optimizing the commissioning schedule of the reliability enhancement project, which is targeted to increase Q3/24 SCO production.
- At AOSP, a 49 day turnaround is targeted to begin in September 2024, when the Scotford Upgrader will run at reduced rates, impacting annual production by approximately 11,000 bbl/d.
The Company continues to progress sustainable production enhancements at both Horizon and AOSP.
- At Horizon, the Company targets to complete the remaining components and tie-ins related to the reliability enhancement project during the planned turnaround in Q2/24.
  - This project targets to increase capacity of the zero decline, high value SCO production over a two year timeframe by shifting the planned turnarounds to once every two years from the current annual cycle, reducing downtime and increasing overall reliability. In 2025, annual production is targeted to increase by approximately 28,000 bbl/d, with the two year average annual SCO capacity targeted to increase by approximately 14,000 bbl/d.
- At the Scotford Upgrader, a debottlenecking project, which targets to add incremental capacity at AOSP of approximately 5,600 bbl/‌d net to Canadian Natural, is targeted to be completed during the planned Fall 2024 turnaround.
- At Horizon, the Company is progressing the Naphtha Recovery Unit Tailings Treatment ("NRUTT") project that targets incremental production of approximately 6,300 bbl/d of SCO following mechanical completion in Q3/27. This project is targeted to reduce GHG emissions, equivalent to 6% of Horizon's total Scope 1 emissions, and will result in lower reclamation costs.

International Exploration and Production

	Three Months Ended
	Mar 31 2024	Dec 31 2023	Mar 31 2023
Crude oil production (bbl/d)	24,823	25,829	27,331
Natural gas production (MMcf/d)	12	13	12

International E&P crude oil production volumes averaged 24,823 bbl/d in Q1/24, a decrease of 9% from Q1/23 levels, reflecting natural field declines and maintenance activities.

MARKETING

		Three Months Ended
		Mar 31 2024			Dec 31 2023			Mar 31 2023
Benchmark Commodity Prices
WTI benchmark price (US$/bbl) ⁽¹⁾	$	76.97		$	78.33		$	76.11
WCS heavy differential (discount) to WTI (US$/bbl)⁽¹⁾	$	(19.34	)	$	(21.90	)	$	(24.74	)
WCS heavy differential as a percentage of WTI (%)⁽¹⁾		25%			28 %			33 %
Condensate benchmark price (US$/bbl)	$	72.79		$	76.22		$	79.83
SCO price (US$/bbl)⁽¹⁾	$	69.43		$	78.64		$	78.18
SCO premium (discount) to WTI (US$/bbl)⁽¹⁾	$	(7.54	)	$	0.31		$	2.07
AECO benchmark price (C$/GJ)	$	1.94		$	2.52		$	4.12
Realized Prices
Exploration & Production liquids realized price (C$/bbl)^(2)(3)(4)(5)	$	70.01		$	69.39		$	58.85
SCO realized price (C$/bbl)^(1)(3)(4)(5)	$	88.84		$	98.73		$	96.07
Natural gas realized price (C$/Mcf)⁽⁴⁾	$	2.55		$	2.80		$	4.27
(1)West Texas Intermediate ("WTI"); Western Canadian Select ("WCS"); Synthetic Crude Oil ("SCO"). (2)Exploration & Production crude oil and NGLs average realized price excludes SCO. (3)Pricing is net of blending costs. (4)Excludes risk management activities. (5)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024 dated May 1, 2024.

Canadian Natural has a balanced and diverse product mix of natural gas, NGLs, heavy crude oil, light crude oil, bitumen and SCO.
WTI prices averaged US$76.97/bbl in Q1/24, comparable to both Q4/23 and Q1/23, although the global crude oil market continues to be impacted by heightened geopolitical tensions.
- WTI forward strip pricing⁽¹⁾ has strengthened for the last nine months of 2024, averaging US$79.95/‌bbl, an improvement of approximately US$3/bbl from Q1/24.
SCO pricing averaged US$69.43/bbl in Q1/24, representing a US$7.54/bbl price discount to WTI, compared to a US$2.07/bbl price premium to WTI in Q1/23. The lower SCO price in Q1/24 was primarily driven by egress constraints in the Western Canadian Sedimentary Basin ("WCSB").
- SCO forward strip pricing⁽¹⁾ has strengthened for the last nine months of 2024, averaging a price premium to WTI of US$2.47/‌bbl, an improvement of approximately US$10/bbl from Q1/24.
The average WCS differential to WTI of US$19.34/bbl in Q1/24 has strengthened from both comparable periods, primarily reflecting the anticipated startup of TMX and stronger US Gulf Coast heavy oil pricing due to lower Mexican imports.
- WCS forward strip pricing⁽¹⁾ has strengthened for the last nine months of 2024, averaging US$13.17/‌bbl, an improvement of approximately US$6/bbl from Q1/24.
The Company continues to evaluate and implement opportunities to maximize netbacks through the diversification of sales and optimized blending and transportation options through diverse market access. Canadian Natural has optionality for crude oil exports, including the following pipeline commitments:
- In Q1/24, the Company increased its commitment on Flanagan South by 55,000 bbl/d to 77,500 bbl/d, further expanding the Company's heavy oil diversification and market access to the USGC.
- 94,000 bbl/d on TMX pipeline that creates additional crude oil market diversification opportunities on the west coast, both by land and by water.
- 10,000 bbl/d on the Base Keystone Pipeline, with direct access to the USGC.

(1) Forward strip pricing as of April 30, 2024.

The North West Redwater ("NWR") refinery primarily utilizes bitumen as feedstock, with production of ultra-low sulphur diesel and other refined products averaging 78,569 bbl/d in Q1/24.
AECO natural gas prices in Q1/24 compared to Q1/23 and Q4/23 reflect lower NYMEX benchmark pricing, increased production in the WCSB and higher storage inventories resulting from mild winter weather.
- In 2024, the Company is targeting to use the equivalent of approximately 38% of its budgeted natural gas production in its operations, with approximately 25% targeted to be sold at AECO/Station 2 pricing, and approximately 37% targeted to be exported to other North American and international markets capturing higher natural gas prices, maximizing value from its diversified natural gas marketing portfolio.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE HIGHLIGHTS

Canada and Canadian Natural are well positioned to deliver affordable, reliable, safe and responsibly produced energy that the world needs, through leading ESG performance. Canadian Natural's diverse portfolio is supported by a significant amount of long life low decline assets which have low risk, high value reserves that require low maintenance capital. This allows the Company to remain flexible with our capital allocation and creates an ideal opportunity to pilot and apply technologies for GHG emissions reductions. Canadian Natural continues to invest in a range of technologies to reduce emissions, such as solvents for enhanced recovery and Carbon Capture, Utilization and Storage ("CCUS") projects. Our culture of continuous improvement provides a significant advantage to delivering on our strategy of investing in GHG technologies across our assets, including opportunities for methane emissions reduction.

Environmental Targets

Canadian Natural is committed to reducing our environmental footprint and as previously announced, has committed to the following environmental targets:

40% reduction in corporate Scope 1 and Scope 2 absolute GHG emissions by 2035, from a 2020 baseline
50% reduction in North America E&P (including thermal in situ) methane emissions by 2030, from a 2016 baseline
40% reduction in thermal in situ fresh water usage intensity by 2026, from a 2017 baseline
40% reduction in mining fresh river water usage intensity by 2026, from a 2017 baseline

Canadian Natural has a defined pathway to achieve long-term emissions reductions with an integrated GHG emissions management strategy that includes ongoing investments in technology and innovation while transferring technology across the Company. The areas of focus include, but are not limited to: carbon capture, sequestration/storage and utilization, the use of solvents, energy/steam efficiencies, methane reduction, and tailings and water management.

Pathways Alliance

The six major oil sands companies in the Pathways Alliance ("Pathways"), including Canadian Natural, operate approximately 95% of Canada's oil sands production. The goal of this unique alliance is to work together with governments to achieve net zero emissions from oil sands operations by 2050, support Canada in meeting its climate commitments and be the preferred source of crude oil globally. Pathways has a defined plan, including its foundational carbon capture and storage ("CCS") project involving a CO₂ transportation line connecting Fort McMurray and Cold Lake to a carbon sequestration hub.

Pathways continues to work together with governments on the necessary co-investment and regulatory certainty needed to proceed. As a step in moving the project forward, Canadian Natural, on behalf of the Pathways Alliance, commenced regulatory applications in March 2024 to the Alberta Energy Regulator for the proposed CO₂ Transportation Network and Storage Hub. Project engineering and environmental field programs are on track to meet timelines. Multiple feasibility studies on phase-one capture facilities, with engineering and design work continue to progress. Stakeholder engagement and consultation is ongoing with Indigenous and local communities in northern Alberta related to the Pathways CCS project.

Government Support for Emissions Reductions and Carbon Capture, Utilization and Storage

The Government of Canada announced a Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap on December 7, 2023 with plans to publish draft regulations by mid-2024. The framework proposes to cap and cut emissions from the oil and natural gas sector through implementation of a national cap-and-trade system. The oil and natural gas sector has made significant progress in GHG emissions reductions along with investments in technology and innovation that have been enabled under existing carbon pricing systems. As such, the proposed oil and natural gas sector emissions cap is unnecessary, exceedingly complex and undermines the investor confidence required for large-scale, long-term emission reduction initiatives.

Canadian Natural is a leader in CCUS and GHG reduction projects and sees many opportunities to work collaboratively with industry peers and governments to advance investments in CCUS and to achieve meaningful GHG emissions reductions in support of Canada's climate goals. The Government of Canada has proposed an investment tax credit ("ITC") for CCUS projects for all sectors across Canada that would offer a refundable ITC of up to 50% on capture equipment and 37.5% on qualified carbon transportation, storage or usage equipment from 2022 to 2030. Additionally, the Government of Alberta announced it would provide a 12% tax credit on eligible capital costs associated with building new CCUS projects. It remains important for governments to work together with industry to ensure that policy and regulatory frameworks deliver the required support to enable CCUS project development.

Canadian Natural will continue to provide input to government on the importance of balancing environmental and economic objectives along with being able to support Canada's allies with energy security. By working together, industry and governments have the opportunity to help achieve climate goals, meet economic objectives and support Canada's role in energy security.

ADVISORY

Special Note Regarding Forward-Looking Statements

Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words "believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict", "should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed", "aspiration" or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to the Company's capital budget, expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, abandonment expenditures, income tax expenses, and other targets provided throughout this document and the Management's Discussion and Analysis ("MD&A") of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including, without limitation, those in relation to: the Company's assets at Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project ("AOSP"), the Primrose thermal oil projects, the Pelican Lake water and polymer flood projects, the Kirby thermal oil sands project, the Jackfish thermal oil sands project and the North West Redwater bitumen upgrader and refinery; construction by third parties of new, or expansion of existing, pipeline capacity or other means of transportation of bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or synthetic crude oil ("SCO") that the Company may be reliant upon to transport its products to market; the abandonment and decommissioning of certain assets and the timing thereof; the development and deployment of technology and technological innovations; the financial capacity of the Company to complete its growth projects and responsibly and sustainably grow in the long-term; and the impact of the Pathways Alliance ("Pathways") initiative and activities, government support for Pathways and the ability to achieve net zero emissions from oil sands production, also constitute forward-looking statements. These forward-looking statements are based on annual budgets and multi-year forecasts, and are reviewed and revised throughout the year as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and NGLs reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserves and production estimates.

The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry in which the Company operates, which speak only as of the earlier of the date such statements were made or as of the date of the report or document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such risks and uncertainties include, among others: general economic and business conditions (including as a result of the actions of the Organization of the Petroleum Exporting Countries Plus ("OPEC+"), the impact of armed conflicts in the Middle East, the impact of the Russian invasion of Ukraine, increased inflation, and the risk of decreased economic activity resulting from a global recession) which may impact, among other things, demand and supply for and market prices of the Company's products, and the availability and cost of resources required by the Company's operations; volatility of and assumptions regarding crude oil, natural gas and NGLs prices; fluctuations in currency and interest rates; assumptions on which the Company's current targets are based; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the ability of the Company to prevent and recover from a cyberattack, other cyber-related crime and other cyber-related incidents; industry capacity; ability of the Company to implement its business strategy, including exploration and development activities; the Company's ability to implement strategies and leverage technologies to meet climate change initiatives and emissions targets on the expected timelines; the impact of competition; the Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company to complete capital programs; the Company's ability to secure adequate transportation for its products; unexpected disruptions or delays in the mining, extracting or upgrading of the Company's bitumen products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; ability of the Company to attract the necessary labour required to build, maintain, and operate its thermal and oil sands mining projects; operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in the mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; the Company's ability to meet its targeted production levels; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserves estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations and the impact of climate change initiatives on capital expenditures and production expenses); interpretations of applicable tax laws and regulations; asset retirement obligations; the sufficiency of the Company's liquidity to support its growth strategy and to sustain its operations in the short, medium, and long-term; the strength of the Company's balance sheet; the flexibility of the Company's capital structure; the adequacy of the Company's provision for taxes; the impact of legal proceedings to which the Company is party; and other circumstances affecting revenues and expenses.

The Company's operations have been, and in the future may be, affected by political developments and by national, federal, provincial, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon its assessment of the future considering all information then available.

Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this document or the Company's MD&A could also have adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by applicable law, the Company assumes no obligation to update forward-looking statements in this document or the Company's MD&A, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company's estimates or opinions change.

Special Note Regarding Currency, Financial Information and Production

This document should be read in conjunction with the Company's unaudited interim consolidated financial statements (the "financial statements") and the Company's MD&A for the three months ended March 31, 2024, and audited consolidated financial statements for the year ended December 31, 2023. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's financial statements and MD&A for the three months ended March 31, 2024 have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").

Production volumes and per unit statistics are presented throughout this document on a "before royalties" or "company gross" basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. In addition, reference is made to crude oil and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of this document, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production on an "after royalties" or "company net" basis is also presented for information purposes only.

Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2023, is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov. Information on the Company's website does not form part of and is not incorporated by reference in the Company's MD&A.

Special Note Regarding Non-GAAP and Other Financial Measures

This document includes references to non-GAAP measures, which include non-GAAP and other financial measures as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure. These financial measures are used by the Company to evaluate its financial performance, financial position or cash flow and include non-GAAP financial measures, non-‍GAAP ratios, total of segments measures, capital management measures, and supplementary financial measures. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP and other financial measures. The non-GAAP and other financial measures used by the Company may not be comparable to similar measures presented by other companies, and should not be considered an alternative to or more meaningful than the most directly comparable financial measure presented in the Company's financial statements, as applicable, as an indication of the Company's performance. Descriptions of the Company's non-GAAP and other financial measures included in this document, and reconciliations to the most directly comparable GAAP measure, as applicable, are provided below as well as in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024.

Break-even WTI Price

The break-even WTI price is a supplementary financial measure that represents the equivalent US dollar WTI price per barrel where the Company's adjusted funds flow is equal to the sum of maintenance capital and dividends. The Company considers the break-even WTI price a key measure in evaluating its performance, as it demonstrates the efficiency and profitability of the Company's activities. The break-even WTI price incorporates the non-GAAP financial measure adjusted funds flow as reconciled in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A. Maintenance capital is a supplementary financial measure that represents the capital required to maintain annual production at prior period levels.

Capital Budget

Capital budget is a forward looking non-GAAP financial measure. The capital budget is based on net capital expenditures (Non-GAAP Financial Measure) and excludes net acquisition costs. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for more details on net capital expenditures.

Capital Efficiency

Capital efficiency is a supplementary financial measure that represents the capital spent to add new or incremental production divided by the current rate of the new or incremental production. It is expressed as a dollar amount per flowing volume of a product ($‍/‍bbl/‍‍d or $/‍BOE‍/‍d). The Company considers capital efficiency a key measure in evaluating its performance, as it demonstrates the efficiency of the Company's capital investments.

Free Cash Flow Policy in 2023 and 2024

Free cash flow is a non-GAAP financial measure. The Company considers free cash flow a key measure in demonstrating the Company's ability to generate cash flow to fund future growth through capital investment, pay returns to shareholders and to repay or maintain net debt levels, pursuant to the free cash flow allocation policy.

The Company's free cash flow is used to determine the target amount of shareholder returns after dividends. The calculation in determining free cash flow varies depending on the Company's net debt position, and as a result of achieving $10 billion in net debt at the end of 2023, the Company's free cash flow calculation has changed in 2024, when compared to 2023 as follows:

Allocation of Free Cash Flow in 2024

As net debt of $10 billion was achieved at the end of 2023, commencing in 2024, the Company will target to return 100% of free cash flow to shareholders. Free cash flow is calculated as adjusted funds flow less dividends on common shares, net capital expenditures and abandonment expenditures. The Company targets to manage the allocation of free cash flow on a forward looking annual basis, while managing working capital and cash management as required.

The Company's free cash flow for the three months ended March 31, 2024 is shown below:

		Three Months Ended
($ millions)		Mar 31 2024
Adjusted funds flow⁽¹⁾	$	3,138
Less: Dividends on common shares		1,076
Net capital expenditures⁽²⁾		1,113
Abandonment expenditures		162
Free cash flow	$	787
(1)Refer to the descriptions and reconciliations to the most directly comparable GAAP measure, which are provided in the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024. (2)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months ended March 31, 2024, dated May 1, 2024.

Allocation of Free Cash Flow in 2023

When net debt was between $10 billion and $15 billion, as was the case in 2023, approximately 50% of free cash flow was allocated to shareholder returns and 50% was allocated to the balance sheet, less strategic growth/acquisition opportunities. In 2023, free cash flow of $6.9 billion was calculated as adjusted funds flow of $15.3 billion less dividends on common shares of $3.9 billion, base capital expenditures of $4.0 million and abandonment expenditures of $0.5 billion.

Long-term Debt, net

Long-term debt, net (also referred to as net debt) is a capital management measure that is calculated as current and long-term debt less cash and cash equivalents.

($ millions)		Mar 31 2024		Dec 31 2023		Mar 31 2023
Long-term debt	$	11,040	$	10,799	$	12,024
Less: cash and cash equivalents		767		877		92
Long-term debt, net	$	10,273	$	9,922	$	11,932

CONFERENCE CALL

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) will be issuing its 2024 First Quarter Earnings Results on Thursday, May 2, 2024 before market open.

A conference call will be held at 7:00 a.m. MDT / 9:00 a.m. EDT on Thursday, May 2, 2024.

Dial-in to the live event:

North America 1-800-717-1738 / International 001-289-514-5100.

Listen to the audio webcast:

Access the audio webcast on the home page of our website, www.cnrl.com.

Conference call playback:

North America 1-888-660-6264 / International 001-289-819-1325 (Passcode: 56079#)

Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.

Canadian Natural Resources LIMITED
T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com
2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8
www.cnrl.com

SCOTT G. STAUTH
President

MARK A. STAINTHORPE
Chief Financial Officer

LANCE J. CASSON
Manager, Investor Relations

Trading Symbol - CNQ
Toronto Stock Exchange
New York Stock Exchange

Corporate Logo

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/207678

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Canadian Natural Resources CNQ:CC TSX:CNQ Energy Investing

CNQ:CC

Canadian Natural Resources Limited Reports Voting Results at Annual and Special Meeting

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) held its Annual and Special Meeting of Shareholders on May 2, 2024. The result of the vote by shareholders for each resolution is reported below.

The election of the following nominees as directors of the Corporation for the ensuing year or until their successors are elected or appointed.
	Votes For	Votes Withheld
Catherine M. Best	739,666,794 97.19%	21,395,027 2.81%
M. Elizabeth Cannon	755,414,889 99.26%	5,646,932 0.74%
N. Murray Edwards	734,115,206 96.46%	26,946,615 3.54%
Christopher L. Fong	730,264,360 95.95%	30,797,461 4.05%
Ambassador Gordon D. Giffin	681,630,086 89.56%	79,431,703 10.44%
Wilfred A. Gobert	749,993,920 98.55%	11,067,902 1.45%
Christine M. Healy	759,396,832 99.78%	1,664,989 0.22%
Steve W. Laut	752,522,642 98.88%	8,539,180 1.12%
Honourable Frank J. McKenna	713,843,507 93.80%	47,218,314 6.20%
Scott G. Stauth	755,136,229 99.22%	5,925,592 0.78%
David A. Tuer	721,224,440 94.77%	39,837,382 5.23%
Annette M. Verschuren	757,804,674 99.57%	3,257,147 0.43%

	Votes For	Votes Withheld
The appointment of PricewaterhouseCoopers LLP as auditors of the Corporation for the ensuing year and to authorize the Audit Committee of the Board of Directors to fix their remuneration.	733,200,212 94.14%	45,678,373 5.86%
	Votes For	Votes Against
Vote on Share Split of Issued and Outstanding Common Shares of the Corporation be subdivided on a two for one basis.	774,321,586 99.41%	4,556,996 0.59%
	Votes For	Votes Against
On an advisory basis, approval of the Corporation's approach to executive compensation.	748,228,501 98.31%	12,833,315 1.69%

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Canadian Natural Resources Limited Announces Further Details Regarding Share Split

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) ("Canadian Natural") announced today that it has set June 3, 2024 as the record date (the "Record Date") for the previously announced two for one split of its common shares (the "Share Split"). The Share Split was approved by shareholders of Canadian Natural at its annual and special meeting of shareholders held on May 2, 2024. On June 10, 2024 (the "Payment Date"), shareholders of record as of the close of business on the Record Date will receive one additional share for every one common share held.

As of the close of markets on May 2, 2024, Canadian Natural had 1,068,104,423 common shares issued and outstanding. Adjusted for the Share Split, there would have been 2,136,208,846 common shares issued and outstanding.

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Canadian Natural Resources Limited Announces Quarterly Dividend

Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) announces that its Board of Directors has declared a quarterly cash dividend on its common shares of $1.05 (one dollar and five cents) per common share on a pre-stock split basis or $0.525 (fifty-two and one half cents) per common share after giving effect to the two for one stock split of the common shares, subject to approval at the Company's Annual and Special Meeting of Shareholders on May 2, 2024. The dividend will be payable on July 5, 2024 to shareholders of record at the close of business on June 17, 2024.

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Canadian Natural Resources Limited Announces 2023 Fourth Quarter and Year End Results

Highlighting a successful 2023, Canadian Natural's (TSX: CNQ) (NYSE: CNQ) Chief Financial Officer, Mark Stainthorpe, stated "Through the Company's effective and efficient operations and disciplined capital allocation, we achieved our net debt level of $10 billion in Q423, earlier than previously forecasted. As per our free cash flow allocation policy, we will now target to return 100% of free cash flow to shareholders through dividends and share buybacks."

Canadian Natural's Vice Chairman, Tim McKay, also commented "In 2023, we delivered on our capital allocation strategy by strengthening our balance sheet, providing significant returns to shareholders and strategically developing our assets. We achieved record annual production while growing our reserves organically on both a total proved and total proved plus probable basis, with reserve replacement ratios of 166% and 194% respectively.

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Canadian Natural Resources Limited Announces 2024 Budget

Canadian Natural's (TSX: CNQ) (NYSE: CNQ) President, Tim McKay, commented on the Company's 2024 budget, "Our teams remain focused on safe, reliable, effective and efficient operations throughout our asset base. Our unique and diversified asset base provides us a key competitive advantage as we can manage the pace and timing of development activities to maximize value growth from our assets. As part of our 2024 budget, the drilling program is weighted towards longer cycle projects in the first half of the year, primarily thermal in situ. During the second half of the year we will focus on shorter cycle development opportunities to better align with incremental market egress and potentially improved commodity pricing, maximizing value for our shareholders.

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Forsys Reports Updated Mineral Resource Estimate for its Norasa Project in Namibia

Forsys Metals Corp. (TSX: FSY) (FSE: F2T) (NSX: FSY) ("Forsys" or the "Company")

Forsys is pleased to provide an update for the Company's Norasa Uranium project ("Norasa ¹ ") which comprises the deposits of Valencia Main and East, ("Valencia"), under Mining Licence (ML-149) and Namibplaas ("Namibplaas") under EPL-3638, (ML-251 pending).

Highlights

Forsys has undertaken a comprehensive review and update of all of the parameters for a Mineral Resource Estimate ("MRE") for the Norasa project using recent drill results together with the 2005-2011 previous MRE data. Confirmatory and geotechnical drilling, in conjunction with new survey information, including topographic surveys, down-the-hole optical televiewer surveys, trajectory surveys, and downhole gamma probe surveys, were used as inputs for mineral resource modelling. Re-interpretation of the previous database utilising all available data and modern estimation approaches has improved the definition of the MRE to more confidently support mine planning. This study, enhanced by an integrated and expanded drill program targeting existing and new areas together with a robust work plan of optimisation process testing and modelling, will help reinforce the upside potential of the Norasa project.

For the overall Norasa project, a conceptual pit constrained MRE for total deposits assessed from previous (2005-2011) and 2023 drilling results is estimated to be:
- Valencia Main Measured and Indicated Resource at 40 ppm U ₃ O ₈ cutoff is estimated to be 152 Mt at 136 ppm eU ₃ O ₈ (equivalent U ₃ O ₈ ). Measured and Indicated contained metal is estimated at 45 Mlbs U ₃ O ₈ , at 40 ppm U ₃ O ₈ cutoff.
- Valencia Main and East Inferred Resources are estimated at 5.7 Mt at 120 ppm eU ₃ O ₈ with 1.3 Mlbs U ₃ O ₈ contained metal oxide, at 40 ppm U ₃ O ₈ cutoff.
- Namibplaas Inferred Resources are estimated to be 218.7 Mt at 85 ppm eU ₃ O ₈ with 41.1 Mlbs U ₃ O ₈ contained metal oxide, at 40 ppm U ₃ O ₈ cutoff.

Pine van Wyk, Country Director for Forsys commented: "The comprehensive work done over the last twelve months on the Norasa Uranium Project has created a solid foundation to advance project development. The revised mineral resource model will help optimise the mine economics and process parameters. Results are expected soon from a column leaching test program currently being undertaken at SGS Laboratories in South Africa, which would establish the design basis of the planned heap leaching pads. With the existing ML149 permitted to commence mining, the large scale Norasa project is well advanced to take advantage of the strong uranium sector fundamentals."

Mineral Resources
Results are reported from recent remodelling of historical (2005-2011) drilling and recent 2023 drilling results. The Mineral Resources are reported within US$120/lb U ₃ O ₈ pit shells, with a cut-off grade of 40 ppm U ₃ O ₈ for each of the deposits at Valencia Main and East, ("Valencia"), under Mining Licence (ML-149) and US$120/lb U ₃ O ₈ at 40 ppm U ₃ O ₈ cutoff at Namibplaas ("Namibplaas") under EPL-3638. The MRE are summarised as follows:

For the overall Norasa project, a conceptual open-pit shell constrained MRE for total deposits assessed from previous (2005-2011) and recent (2023) drilling results is estimated to be Measured and Indicated of 151.9 Mt at 136 ppm eU ₃ O ₈ , with contained metal oxide of 45.4 Mlbs U ₃ O ₈ at Valencia Main. Inferred Resources for the Norasa project are estimated to be 224.5 Mt at 86 ppm eU ₃ O ₈ , with contained metal oxide of 42.6 Mlbs U ₃ O ₈ (refer to Table 1):

Measured and Indicated: 151.9 Mt at 136ppm eU ₃ O ₈ , with contained metal oxide of 45.4 Mlbs for Valencia Main.
Inferred Resource for Valencia Main is estimated to be 4.7 Mt at 121 ppm eU ₃ O ₈ and 1.3 Mlbs eU ₃ O ₈ contained metal oxide.
Inferred Resource for Valencia East is estimated to be 1.0 Mt at 114 ppm eU ₃ O ₈ and 0.3 Mlbs U ₃ O ₈ contained metal oxide; and
Inferred Resource for Namibplaas is estimated to be 218.7 Mt at 85 ppm eU ₃ O ₈ and 41.1 Mlbs U ₃ O ₈ contained metal oxide.

Table 1: Mineral Resource Estimate for Norasa project as at 30 April 2024 at a 40 ppm U ₃ O ₈ cut-off grade.

Class	Deposit	Mass Mt (metric)	Average Grade eU ₃ O ₈ (ppm)	Material Content U ₃ O ₈ Mlbs	Contained Metal U tonnes



Measured	Valencia East
	Valencia Main	7.6	171	2.9	1,099
	Namibplaas
	Norasa	7.6	171	2.9	1,099
Indicated	Valencia East
	Valencia Main	144.3	134	42.6	16,368
	Namibplaas
	Norasa	144.3	134	42.6	16,368
Measured & Indicated	Valencia East
	Valencia Main	151.9	136	45.4	17,467
	Namibplaas
	Norasa	151.9	136	45.4	17,467
Inferred	Valencia East	1.0	114	0.3	97
	Valencia Main	4.7	121	1.3	487
	Namibplaas	218.7	85	41.1	15,817
	Norasa	224.5	86	42.6	16,401

Notes:
1.	All tabulated data have been rounded and as a result minor computational errors may occur.
2.	Mineral Resources, which are not Mineral Reserves, have no demonstrated economic viability. There is no guarantee that all or any part of the mineral resource will be converted into a mineral reserve. The estimate of mineral resources may be materially affected by geology, environment, permitting, legal, title, taxation, socio-political, marketing, or other relevant issues.
3.	The Mineral Resource Statement for Norasa as at 30th April 2024 is reported at a cut-off grade of 40ppm U ₃ O ₈ from within a conceptual pit-shell using the following assumed parameters: Base Uranium Price –USD/lb U ₃ O ₈ : $120 Average Mining Cost at reference elevation (AISC) USD/tonne: Valencia Main $2.38; Valencia East $2.13; Namibplaas $2.29" Average Processing Cost USD/tonne processed: $7.55 Average G&A Overheads USD/tonne processed: $1.04 Process Overall Recovery % U ₃ O ₈ Recovery: 85.0 % Selling Cost Transport USD/lb U ₃ O ₈ : $1.29
4.	From the assumed parameters, a 40 ppm U ₃ O ₈ cut-off grade was calculated, which together with the conceptual pit shell demonstrates reasonable prospects for eventual economic extraction (RPEEE) for the Mineral Resource. The assessment to satisfy the criteria of RPEEE is a high-level estimate and is not an attempt to estimate Mineral Reserves.

Mineral Resource Estimation Methodology

A summary of the Mineral Resource modelling methodology is as follows:

The Mineral Resource was modelled using a combination of Leapfrog Geo ^® and Datamine Studio RM ^® software.
Valencia Main and East data:
- Comprise a combined dataset of 141 diamond (DD), 148 reverse circulation (RC) and 446 percussion (PC) type drill holes (Figure 1).
- Borehole data from Valencia Main and East with XRF assay and calculated equivalent grades (eU ₃ O ₈ ) from gamma-probing for each of the deposits have been used to estimate the Mineral Resource.
- Equivalent uranium grades have been factored to correlate practically well with the XRF data, which constitutes 25 % of the grade data.
- Where XRF data are available these supercede the corresponding probe equivalent grade in the estimation data.
Namibplaas data:
- Comprise a dataset of 530 percussion holes and 40 diamond drill holes (Figure 2).
- Borehole data from Namibplaas XRF assay and calculated equivalent grades (eU ₃ O ₈ ) have been used to estimate the Inferred Mineral Resource.
- Equivalent uranium grades constitute the majority of the grade data and where XRF data are available, ~3.5 % of all grade data, these supercede the probe derived values.
Wireframe interpretations of the logged lithologies were used to define the various geological units.
Mineralisation is strongly associated with alaskite intrusions, that are in turn controlled by a structural architecture that comprises folded and planar strata surfaces, and fold-associated shears and cleavages. Importantly, the orientation of marble strata is a major control on the distribution of uranium mineralisation for REDOX chemistry reasons, at Valencia and the Erongo region alaskite deposits as whole. The alaskite orientations are therefore strataform, except where they have invaded sheared and strongly cleaved antiformal hinge zones, as at Valencia Main. In order to honour the geological controls in the estimates various surfaces were modelled:
- String interpretations of the "stratiform" intrusions were digitised in cross-section and were used to create median surfaces for each of the intrusions.
- The resulting mineralised zone wireframes align with the lithological strata while also cross-cutting the strata in places to accommodate axial-planar mineralisation orientations (see Figure 3).
- The surfaces were then used to guide the orientation of the grade estimate through interpolation of individual dip and dip directions for each model block.
The geometry of the Namibplaas deposit comprises stratiform lithologies that dip toward the southwest. The alaskite intrusives have intruded in a strataform manner and have exploited disruptions in the overall fabric, such as local fold flexures and dilation zones associated with the NE-SW regional extensional setting. In order to honour the geological controls at Namibplaas in the estimates various surfaces were modelled with guidance from the directions of greatest structural continuity to guide implicit modelling:
- Along the strike and dip direction of the host metasediments, and
- Along a shallow-plunging hinge structure that is oriented to the NE, parallel to the regional extension regime.
- Considering that mineralization at Namibplaas is strongly associated with the granitic intrusions, string interpretations of the mid-points of these "stratiform" intrusions were digitized in cross-section, thereafter linked to create median surfaces of each of the alaskite intrusions (see Figure 4).
- The surfaces of the intrusions were then used to guide the orientation of the grade estimate through interpolation of individual dip and dip directions for each model block.
Grade shells using a 40 ppm U ₃ O ₈ threshold were constructed using Leapfrog ^® implicit modelling with directional control surfaces from the geological model.
The model volumes were divided into four domains at Valencia Main and two domains at Namibplaas. Each domain is distinct in terms of its geographic/geometric position as well as statistical / geostatistical parameters.
Ordinary kriging estimation used three-dimensional directional variograms to estimate U ₃ O ₈ grades within the mineralised zones for Valencia Main and Namibplaas. Inverse distance squared interpolation was used for Valancia East. The models underwent validation by comparison of estimated grade values against input sample grades, both visually and statistically.
Volumes covered by 30 m drill-spacing were classified as Indicated Mineral Resources at Valencia. All blocks outside of these volumes within the grade shells that received a grade estimate during the interpolation runs were considered Inferred.
At Namibplaas, although the tight drill spacing of approximately 30 m provides dense coverage of the deposit, the predominance of probe-derived eU ₃ O ₈ assays warrants a confidence level for an Inferred Resource.

30 April 2024 MRE block model and US$120/lb U3O8 pit shells at Valencia Main and Valencia East, ML 149.

Figure 1: 30 April 2024 MRE block model and US$120/lb U ₃ O ₈ pit shells at Valencia Main and Valencia East, ML 149.

30 April 2024 MRE block model and US$120/lb U3O8 pit shells at Namibplaas, EPL 3638.

Figure 2: 30 April 2024 MRE block model and US$120/lb U ₃ O ₈ pit shells at Namibplaas, EPL 3638.

Figure 3 part 1. Figure 3 part 2

Figure 3: Shows the stacked concordant surfaces generated parallel to the 3 marble bands and orientation of mineralisation aligned with the strata and axial planar cleavages in the fold hinge (guiding surfaces hidden) at Valencia.

Shows alaskite midpoint strings (yellow) linked in parallel to the the NE-SW oriented strike of the deposit.

Figure 4: Shows alaskite midpoint strings (yellow) linked in parallel to the the NE-SW oriented strike of the deposit.

In accordance with National Instrument 43-101 ("NI 43-101") a Technical Report outlining the mineral resource estimation will be filed under Forsys' profile on SEDAR+ ( www.sedarplus.ca ) within 45 days of the date of this release.

Assaying and QAQC

Recent (2023) Sampling and Assays
- Samples were taken from the diamond drill cores and RC chips for geochemical assay guided by the routine downhole radiometric probe results, and sent to Trace Elements Analysis Laboratories (Pty) Ltd ("TEA Labs") at Swakopmund for sample preparation and analyses by XRF. For internal quality control purposes TEA Labs has weekly round robins with independent laboratories at Rosh Pinah, Swakop Uranium and Langer Heinrich mines.
- Forsys employs a QAQC programme with Certified Reference Materials (CRMs), blanks, coarse duplicates and pulp duplicates inserted into each batch of samples. The QAQC insert rate comprises 4 % CRMs using three CRM types with different grades of U ₃ O ₈ ; 4 % blanks and 8 % to 10 % duplicates. RC sample batches have three types of duplicates; a field duplicate split at the drill rig; a coarse duplicate split at prescribed intervals at the laboratory; and pulp duplicates, also split at the laboratory. Core samples only have coarse and pulp duplicates split at the laboratory.
- Four-percent of the samples sent to TEA Labs are sent for check analyses at SGS Laboratories (SGS) in South Africa, which serves as the independent accredited laboratory. The sample results are further validated by comparison with the radiometric scans.

Previous Sampling and Assays (2005-2011 Valencia Uranium Limited (VUL)):
- All diamond drill half core and RC samples collected by VUL were assayed at the Setpoint Technology ("Setpoint") laboratory in Johannesburg, South Africa. Setpoint was accredited with the South African Accreditation System (SANAS), accreditation number T0223, and was also an ISO17025 accredited laboratory. Setpoint crushed and pulverised the samples for analysis of U ₃ O ₈ using the XRF pressed pellet method.
- The VUL protocols for the QAQC were as follows:
  - CRMs inserted at a frequency of at least one per 20 samples.
  - Blanks inserted at a frequency of at least one per 50 samples.
  - Duplicates taken at a frequency of at least one per 20 samples.
- The Setpoint laboratory included appropriate quality assurance and quality control (QAQC) procedures during the analysis of the VUL samples by including its own certified reference standards (CRM), blanks and duplicates.
- VUL percussion holes were not physically sampled. Datasets were derived from two downhole probes that were calibrated against the XRF sample assays.
- Snowden reviewed the assay results from Setpoint for the Valencia deposits in 2009 ² for the purposes of resource estimation and considered the QAQC results to be of a high standard of precision, unbiased and accurate.
- Optiro reviewed the assay results from Setpoint for the Namibplaas deposit in 2011 and considered that the results of the QAQC indicate a high level of precision with no bias, no significant contamination and a high degree of accuracy (from Snowden 2009 ² and Optiro 2011 ³ )

Trekkopje Exploration (Goldfields 1974-1984):
- Exploration data derived from Trekkopje Exploration era, up to and including 1984, have not been verified by the QP and therefore were not utilised in this Mineral Resource Estimate.

Workplan

Forsys is undertaking an infill and extension drilling program and optimisation work with the aim of expanding and upgrading the Mineral Resource:

Resource Infill Drilling and Resource Extension Drilling
Total of 85 percussion drill holes for 7,520 metres have been laid out on a 25 x 25 metre grid. The objective is to more than double the quantity of the Measured Mineral Resource. The holes target the 660 m elevation with drill depths up to 100 m from surface and is comparable to the previous Measured Resource grid.

A subsequent program for potential resource extension is planned for the areas adjacent to the Valencia Main deposit; along strike to the west, on the hinge zone to the south, and north of the Main deposit at the Jolie Zone.
Pit Design Modeling
The updated resource block model is used to assess open pit economic models. Pit slope design parameters are being reviewed to include lithological logging and geomechanical test work from additional drilling.
Column Leaching Process Optimization Work
Column Leach tests are presently underway at SGS in South Africa where the columns have been emptied and final analyses and data is pending. The next phase of testing will assess systematic processes to enhance the efficiency and effectiveness of extracting the uranium mineralisation from the ore using sulphuric acid solutions.
Process Design
DRA Global were appointed as the study contractor to deliver engineering to support preliminary cost estimates for a heap leach process. Ongoing engineering and optimisation continues.
Bulk Sampling
After site assessment and selection, a detailed plan is being drawn up to develop a box cut with the objective of retrieving approximately 20,000 tonnes of typical run-of-mine, fresh and representative sample material from the deposit.

Qualified Persons Statement for Metallurgy
Mr Aveshan Naidoo is a Specialist Engineer: Hydromet and Economics, for DRA South Africa Projects (Pty) Ltd of Building 33, Woodlands Office Park, 20 Woodlands Drive, Woodlands, Sandton, 2080. He holds a Bachelor of Science in Chemical Engineering and a Master of Business Administration at the University of Witwatersrand. He is a registered Professional Engineer with the Engineering Council of South Africa (Registration No. 20130523). Mr Naidoo has been practising his profession continuously since 2008 and has 16 years of experience across a range of African projects. He is familiar with NI 43-101 and, by reason of his education, experience, and professional registrations, he fulfils the requirements of an independent Qualified Person as defined in NI 43-101.

Qualified Persons Statement for Mineral Resource
The information in this release that relates to the updated Mineral Resource Estimate for the Norasa Project is based on information compiled or reviewed by Dr Guy Freemantle of The MSA Group (Pty) Ltd., Johannesburg, South Africa. The MSA Group are independent consultants to the Norasa Project, Namibia. Dr Freemantle holds a Bachelor of Science in Geology and a PhD in Geology, both at the University of the Witwatersrand. He is a member of the Society of Economic Geologists (892905); a Fellow of the Geological Society of South Africa (965392); and is registered with SACNASP (Registration 117527). Dr Freemantle has practiced his profession continuously for 14 years and has sufficient experience and knowledge that is relevant to the style of mineralisation and type of deposits under consideration as well as to the activity that is being undertaken to fulfil requirements of a Qualified Person as per NI 43-101. Dr Freemantle consents to this release in the form and context in which it appears.

About Forsys Metals Corp.

Forsys Metals Corp. (TSX: FSY, FSE: F2T, NSX: FSY) is an emerging uranium developer focused on advancing its wholly-owned Norasa Uranium Project, located in the politically friendly jurisdiction of Namibia, Africa. The Norasa Uranium Project is comprised of the Valencia Uranium deposit (ML-149) and the nearby Namibplaas Uranium deposit (EPL-3638). Further information is available at the Company website www.forsysmetals.com

On behalf of the Board of Directors of Forsys Metals Corp. Richard Parkhouse, Director, Investor Relations. For additional information please contact:

Pine van Wyk, Country Director, Forsys
email: pine@forsysmetals.com

Richard Parkhouse, Director, Investor Relations
email: rparkhouse@forsysmetals.com email: info@forsysmetals.com
phone : +44 7730493432

Nikolas Matysek, Communications Manager (Canada)
email: nmatysek@forsysmetals.com

Forward Looking Statement

Certain information contained in this press release constitutes "forward-looking information" , within the meaning of Canadian legislation. Generally, these forward-looking statements can be identified by the use of forward-looking terminology such as "plans", "expects" or "does not expect", "is expected", "budget", "scheduled", "estimates", "forecasts", "intends", "anticipates" or "does not anticipate", or "believes", or variations of such words and phrases or state that certain actions, events or results "may", "could", "would", "might" or "will be taken", "occur", "be achieved" or "has the potential to". Forward looking statements contained in this press release are qualified in their entirety by the inherent risks and uncertainties surrounding future expectations. Among those factors which could cause actual results to differ materially are the following: market conditions and other risk factors listed from time to time in our reports filed with Canadian securities regulators on SEDAR at www.sedar+.com. The forward-looking statements included in this press release are made as of the date of this press release and Forsys Metals Corp disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable securities legislation.

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Baselode Starts Drill Program on Bear Uranium Project : Begins Fleet Space Technologies' ANT survey over ACKIO

1,500 metre inaugural Bear drill program has started targeting 3 areas with 6 to 8 drill holes

Fleet Space Technologies' Ambient Noise Tomography ("ANT") survey, a passive, seismic method for generating 3D subsurface models is being deployed over ACKIO

Baselode Energy Corp. (TSXV: FIND) (OTCQB: BSENF) ("Baselode" or the "Company") is pleased to announce the starts of an inaugural drill program and ANT geophysical survey on its Bear ("Bear") and Hook ("Hook") uranium projects, respectively, in the Athabasca Basin area, northern Saskatchewan (see Figure 1).

"We're excited to start this drill campaign on Bear. Our target generation has identified areas of potential structural disruption and hydrothermal fluid alteration along the uranium-fertile Wollaston-Mudjatik transition zone that hosts numerous high-grade uranium deposits. We've identified 3 main targets areas we'll be drilling at the intersection points of NE-SW-trending layers and cross-cutting NW-SE-oriented structures (Figure 2). We believe the latter structures may have controlled anomalous uranium intersected in historic drill holes.

We're also happy to announce we've started laying out and acquiring data from Fleet Space Technologies' ANT survey deployed over ACKIO. We hope to map out the extent of ACKIO's Athabasca sandstone outlier and the deep structural roots of the uranium mineralization system. We believe ACKIO continues at depth, including mineralization along the sandstone-basement fault zone. We look forward to testing these targets when we begin our next ACKIO drill program in June," stated James Sykes, CEO, President, and Director of Baselode.

Please watch the Company's video (below) to understand the target generation ideas for the Bear drill program.

Bear - 2024 Exploration Targets Defined

Cannot view this video? Visit:
https://www.youtube.com/watch?v=anLYo83AUko

Bear Drill Program Details
The recently started Bear drill program is planned for 1,500 metres with 6 to 8 drill holes targeting 2 to 3 different target areas. The helicopter-support program allows expedient drill targeting and lessens environment impacts. The Company has received the necessary permits to complete the program.

Hook ANT Program Details
"Fleet Space Technologies has developed an innovative high-resolution, ground-based, satellite-connected ambient noise tomography ("ANT") survey to produce a 3D model of the subsurface. The survey will be completed over ACKIO and other areas of interest, with data expected to be received and interpreted prior to starting diamond drilling on Hook in June. The Company has received the necessary permits to complete the program.

About Baselode Energy Corp.
Baselode controls 100% of approximately 272,804 hectares for exploration in the Athabasca Basin area of northern Saskatchewan, Canada. The land package is free of any option agreements or underlying royalties.

The Company discovered the ACKIO near-surface, uranium prospect in September 2021. ACKIO measures greater than 375 m along strike, greater than 150 m wide, comprised of at least 9 separate uranium Pods, with mineralization starting as shallow as 28 m and 32 m beneath the surface in Pods 1 and 7, respectively, and down to approximately 300 m depth beneath the surface with the bulk of mineralization occurring in the upper 120 m. ACKIO remains open at depth, and to the north, south and east.

Baselode's Athabasca 2.0 exploration thesis focuses on discovering near-surface, basement-hosted, high-grade uranium orebodies outside the Athabasca Basin. The exploration thesis is further complemented by the Company's preferred use of innovative and well-understood geophysical methods to map deep structural controls to identify shallow targets for diamond drilling.

QP Statement
The technical information contained in this news release has been reviewed and approved by Cameron MacKay, P.Geo., Vice-President, Exploration & Development for Baselode Energy Corp., who is considered to be a Qualified Person as defined in "National Instrument 43-101, Standards of Disclosure for Mineral Projects."

For further information, please contact:

James Sykes, CEO, President and Director
Baselode Energy Corp.
jsykes@oregroup.ca
306-221-8717
www.baselode.com

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the TSX Venture Exchange policies) accepts responsibility for the adequacy or accuracy of this release.

Certain information in this press release may contain forward-looking statements. This information is based on current expectations that are subject to significant risks and uncertainties that are difficult to predict. Actual results might differ materially from results suggested in any forward-looking statements. Baselode Energy Corp. assumes no obligation to update the forward-looking statements, or to update the reasons why actual results could differ from those reflected in the forward looking-statements unless and until required by securities laws applicable to Baselode Energy Corp. Additional information identifying risks and uncertainties is contained in the Company's filings with Canadian securities regulators, which filings are available under Baselode Energy Corp. profile at www.sedarplus.ca.

This news release does not constitute an offer to sell or a solicitation of an offer to buy any of the securities in the United States. The securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act") or any state securities laws and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. Persons unless registered under the U.S. Securities Act and applicable state securities laws, unless an exemption from such registration is available.

FIGURE 1 - Baselode projects location map. ACKIO uranium prospect identified with yellow circle.

To view an enhanced version of this graphic, please visit:
https://images.newsfilecorp.com/files/6412/207569_3b7b7a66048c29e0_007full.jpg

FIGURE 2 – Bear Project Compilation Map.

To view an enhanced version of this graphic, please visit:
https://images.newsfilecorp.com/files/6412/207569_3b7b7a66048c29e0_008full.jpg

Corporate Logo

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/207569

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			Three Months Ended						Year Ended
($ millions, except per common share amounts)			Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Net earnings		$	2,627	$	2,344	$	1,520	$	8,233	$	10,937
Per common share	- basic	$	2.43	$	2.15	$	1.37	$	7.54	$	9.64
	- diluted	$	2.41	$	2.13	$	1.36	$	7.47	$	9.52
Adjusted net earnings from operations⁽¹⁾		$	2,546	$	2,850	$	2,194	$	8,533	$	12,863
Per common share	- basic⁽²⁾	$	2.36	$	2.61	$	1.98	$	7.82	$	11.33
	- diluted⁽²⁾	$	2.34	$	2.59	$	1.96	$	7.74	$	11.19
Cash flows from operating activities		$	4,815	$	3,498	$	4,544	$	12,353	$	19,391
Adjusted funds flow⁽¹⁾		$	4,419	$	4,684	$	4,176	$	15,274	$	19,791
Per common share	- basic⁽²⁾	$	4.09	$	4.30	$	3.78	$	14.00	$	17.44
	- diluted⁽²⁾	$	4.05	$	4.26	$	3.73	$	13.86	$	17.22
Cash flows used in investing activities		$	946	$	1,199	$	1,262	$	4,858	$	4,987
Net capital expenditures⁽³⁾		$	975	$	1,108	$	1,233	$	4,909	$	5,136
Abandonment expenditures, net ⁽¹⁾		$	149	$	123	$	84	$	509	$	335
Daily production, before royalties
Natural gas (MMcf/d)			2,231		2,151		2,115		2,151		2,090
Crude oil and NGLs (bbl/d)			1,047,541		1,035,153		942,258		973,530		933,149
Equivalent production (BOE/d)⁽⁴⁾			1,419,313		1,393,614		1,294,679		1,332,105		1,281,434
(1)Non-GAAP Financial Measure. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2023 dated February 28, 2024. (2)Non-GAAP Ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2023 dated February 28, 2024. (3)Non-GAAP Financial Measure. The composition of this measure has been updated for all periods presented. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2023 dated February 28, 2024. (4)A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, or to compare the value ratio using current crude oil and natural gas prices since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Crude oil and NGLs - excluding Thermal In Situ Oil Sands
	Three Months Ended			Year Ended
	Dec 31 2023	Sep 30 2023	Dec 31 2022	Dec 31 2023	Dec 31 2022
Crude oil and NGLs production (bbl/d)	243,157	232,496	233,371	234,100	227,953
Net wells targeting crude oil	42	42	71	173	214
Net successful wells drilled	42	42	71	171	213
Success rate	100%	100 %	100 %	99%	99 %

	Three Months Ended			Year Ended
	Dec 31 2023	Sep 30 2023	Dec 31 2022	Dec 31 2023	Dec 31 2022
Crude oil production (bbl/d)	25,829	24,719	26,915	26,091	27,233
Natural gas production (MMcf/d)	13	12	10	12	15

		Three Months Ended						Year Ended
		Dec 31 2023		Sep 30 2023		Dec 31 2022		Dec 31 2023		Dec 31 2022
Crude oil and NGLs pricing
WTI benchmark price (US$/bbl) ⁽¹⁾	$	78.33	$	82.18	$	82.62	$	77.61	$	94.23
WCS Heavy Differential from WTI (US$/bbl)	$	21.90	$	12.86	$	25.65	$	18.62	$	18.26
WCS heavy differential as a percentage of
WTI (%) ⁽²⁾		28%		16 %		31 %		24%		19 %
SCO benchmark price (US$/bbl)	$	78.64	$	84.99	$	86.78	$	79.64	$	98.66
Condensate benchmark price (US$/bbl)	$	76.22	$	77.91	$	83.33	$	76.55	$	93.69
Exploration & Production liquids realized
pricing (C$/bbl)⁽³⁾⁽⁴⁾	$	69.39	$	87.83	$	69.34	$	72.36	$	90.64
SCO realized pricing (C$/bbl)⁽⁴⁾⁽⁵⁾	$	98.73	$	108.55	$	103.79	$	100.06	$	117.69
Natural gas pricing
AECO benchmark price (C$/GJ)	$	2.52	$	2.26	$	5.29	$	2.77	$	5.28
Natural gas realized pricing (C$/Mcf) ⁽⁵⁾	$	2.80	$	2.81	$	6.39	$	3.10	$	6.55
(1)West Texas Intermediate ("WTI"). (2)Western Canadian Select ("WCS"). (3)Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities. (4)Non-GAAP ratio. Refer to the "Non-GAAP and Other Financial Measures" section of the Company's MD&A for the three months and year ended December 31, 2023 dated February 28, 2024. (5)Pricing is net of blending costs and excluding risk management activities.

	Light and Medium Crude Oil (MMbbl)	Primary Heavy Crude Oil (MMbbl)	Pelican Lake Heavy Crude Oil (MMbbl)	Bitumen (Thermal Oil) (MMbbl)	Synthetic Crude Oil (MMbbl)	Natural Gas (Bcf)	Natural Gas Liquids (MMbbl)	Barrels of Oil Equivalent (MMBOE)
Total Company
Proved
Developed Producing	114	106	203	653	6,827	4,730	138	8,829
Developed Non-Producing	5	7	-	38	-	229	7	95
Undeveloped	100	80	55	2,596	83	10,045	398	4,986
Total Proved	218	193	258	3,287	6,910	15,005	543	13,910
Probable	87	95	107	1,903	550	9,279	305	4,594
Total Proved plus Probable	305	288	365	5,191	7,460	24,284	848	18,504

Drilling Activity	Year Ended December 31
	2023		2022
(number of wells)	Gross	Net	Gross	Net
Crude oil⁽¹⁾	228	221	332	317
Natural gas	78	61	100	72
Dry	2	2	1	1
Subtotal	308	284	433	390
Stratigraphic test / service wells	481	419	530	452
Total	789	703	963	842
Success rate (excluding stratigraphic test / service wells)		99%		99 %
(1)Includes bitumen wells.

		2024	2025	2026	2027	2028
Crude Oil and NGLs
WTI	US$/bbl	73.67	74.98	76.14	77.66	79.22
WCS	C$/bbl	76.74	79.77	81.12	82.88	85.04
Canadian Light Sweet	C$/bbl	92.91	95.04	96.07	97.99	99.95
Cromer LSB	C$/bbl	93.57	95.86	96.46	98.39	100.36
Edmonton C5+	C$/bbl	96.79	98.75	100.71	102.72	104.78
Brent	US$/bbl	78.00	79.18	80.36	81.79	83.41

AECO	C$/MMBtu	2.20	3.37	4.05	4.13	4.21
BC Westcoast Station 2	C$/MMBtu	2.06	3.25	3.93	4.01	4.09
Henry Hub	US$/MMBtu	2.75	3.64	4.02	4.10	4.18
All prices increase at a rate of 2% per year after 2028. A foreign exchange rate of 0.7517 US$/C$ was used for 2024 and 2025, and 0.7550 US$/C$ was used for 2026 and thereafter in the year end 2023 evaluation.

2024 Targeted Production⁽¹⁾(before royalties)	2024 Budget
Natural gas (MMcf/d)	2,120 - 2,230
Conventional E&P Crude Oil & NGLs (Mbbl/d)	253 - 265
Thermal and Oil Sands Mining & Upgrading (Mbbl/d)	724 - 743
Total Liquids (Mbbl/d)	977 - 1,008
Total MBOE/d	1,330 - 1,380

2024 Capital Budget⁽¹⁾($ millions)		2024 Budget
Conventional E&P (excluding Thermal)	$	2,540
Thermal and Oil Sands Mining & Upgrading	$	2,880
Total	$	5,420

Drillhole Information							Anomalous Uranium U ₃ O ₈ (ppm) ¹
ID	Target	Dip (°)	Azi (°)	Cover (m)	Total Depth (m)	# Samples	From (m)	To (m)	Interval (m)	Interval Value	Max. Value
FN24001	P03	-50	135	5.8	230	120	5.8	196.6		NAR	36
							196.6	197.1	0.5	378	378
							197.1	199.5		NAR	86
							199.5	201.1	1.6	182	321
							201.1	203.1		NAR	27
							203.1	203.8	0.7	105	105
							203.8	205.7		NAR	61
							205.7	206.3	0.6	345	345
							206.3	208.5		NAR	42
							208.5	209.0	0.5	130	130
							209.0	230		NAR	8
FN24002	P08	-47	120	30.5	144	46	34.0	40.6		NAR	51
							40.6	41.2	0.5	103	103
							41.2	42.3		NAR	98
							42.3	47.0	4.7	316	572
							47.0	67.6		NAR	49
							67.6	68.4	0.8	110	110
							68.4	69.4		NAR	22
							69.4	71.0	1.6	128	132
							71.0	109.5		NAR	96
FN24003 ²	P12	-47	315	2.5	106	39	2.5	94.0		NAR	11

Canadian Natural Resources Limited Announces 2024 First Quarter Results

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